hughes bakken reality check: the nation’s number two tight oil play after a year of low oil prices

7/23/2019 Hughes Bakken Reality Check: The Nations Number Two Tight Oil Play After a Year Of Low Oil Prices

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J. DAVID HUGHES

THE NATIONS NUMBER TWO TIGHT OIL PLAY

AFTER A YEAR OF LOW OIL PRICES

BAKKEN REALITY CHECK

FALL 2015


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B KKENRE LITY CHECK

The Nations Number Two Tight Oil Play After A Year Of Low Oil Prices

J. David Hughes

Fall 2015


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Visit shalebubble.org

for more information and related resources.

About the Author

David Hughes is an earth scientist who has studied the energy resources of Canada for four decades, including 32

years with the Geological Survey of Canada as a scientist and research manager. He developed the National Coal

Inventory to determine the availability and environmental constraints associated with Canadas coal resources. As

Team Leader for Unconventional Gas on the Canadian Gas Potential Committee, he coordinated the publication of

a comprehensive assessment of Canadas unconventional natural gas potential.

Over the past decade, Hughes has researched, published and lectured widely on global energy and sustainabilityissues in North America and internationally. His work with Post Carbon Institute includes: a series of papers

(2011) on the challenges of natural gas being a "bridge fuel" from coal to renewables; Drill, Baby, Drill(2013),

which took a far-ranging look at the prospects for various unconventional fuels in the United States; Drilling

California(2013), which critically examined the U.S. Energy Information Administrations (EIA) estimates of

technically recoverable tight oil in the Monterey Shale, which the EIA claimed constituted two-thirds of U.S. tight oil

(the EIA subsequently wrote down its resource estimate for the Monterey by 96%); Drilling Deeper(2014), which

challenged the U.S. Department of Energys expectation of long-term domestic oil and natural gas abundance with

an in-depth assessment of all drilling and production data from the major shale plays through mid-2014; and

Shale Gas Reality Check(2015) and Tight Oil Reality Check(2015), updates to Drilling Deeper. Separately from

Post Carbon, Hughes authored BC LNG: A Reality Checkin 2014 andA Clear View of BC LNGin 2015, which

examined the issues surrounding a proposed massive scale-up of shale gas production in British Columbia for

LNG export.

Hughes is president of Global Sustainability Research, a consultancy dedicated to research on energy and

sustainability issues. He is also a board member of Physicians, Scientists & Engineers for Healthy Energy (PSE

Healthy Energy) and is a Fellow of Post Carbon Institute. Hughes contributed to Carbon Shift, an anthology edited

by Thomas Homer-Dixon on the twin issues of peak energy and climate change, and his work has been featured in

Nature, Canadian Business, Bloomberg, USA Today, as well as other popular press, radio, and television.

About Post Carbon Institute

Post Carbon Institutes mission is to lead the transition to a more resilient, equitable, and sustainable world byproviding individuals and communities with the resources needed to understand and respond to the interrelatedenvironmental, energy, economic, and equity crises of the 21st century.

Bakken Reality Check: The Nation's Number Two Tight Oil Play After A Year Of Low Oil Prices

By J. David Hughes

In association with Post Carbon Institute

Copyright 2015 by J. David Hughes. All rights reserved. Published October 2015.

For reprint requests and other inquiries, contact:

Post Carbon Institute, 613 Fourth St., Suite 208, Santa Rosa, California, 95404

Cover image (cc-by-nd) National Parks Conservation Association.


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CONTENTS1 Bakken Production Overview ......................................................................................................................... 1

2 Dominance of Sweet Spots ............................................................................................................................ 7

3 Technology Improvement Meets Geology ................................................................................................... 10

4 Future Outlook .............................................................................................................................................. 12

5 Summary and Implications .......................................................................................................................... 14

6 Appendix: Well Addition Rate Versus Production Change and Total Production by County..................... 15

FIGURESFigure 1. Oil production in the Bakken Play from 2003 through June 2015. ...................................................... 1

Figure 2. Cumulative oil and gas production in the Bakken Play by county through July 2015. ......................... 2

Figure 3. Bakken Play oil production by county from 2006 through June 2015.................................................. 3

Figure 4. Oil production in individual counties from 2006 through June, 2015. ................................................. 4

Figure 5. Bakken Play oil production change per month versus new producing wells added per monthfrom 2006 through June 2015. .......................................................................................................... 5

Figure 6. Average production of Bakken wells by county from 2010 through June 2015. ................................. 6

Figure 7. Distribution and initial oil production (highest month) of wells in the Bakken Play of NorthDakota and Montana as of June 2014. .............................................................................................. 7

Figure 8. Type well decline curves by county for the Bakken Play using data to year-end 2014. ....................... 8

Figure 9. Estimated ultimate oil recovery (EUR) by county in the Bakken Play. ................................................... 9

Figure 10. Average production rate of Bakken wells by county over the first six-months of production. ......... 10

Figure 11. Historical production from the Bakken Play using Drillinginfo and EIA Drilling ProductivityReport (DPR) data. ............................................................................................................................. 12

Figure 12. Dunn County oil production change per month versus new producing wells added per monthfrom 2006 through June, 2015. ....................................................................................................... 15

Figure 13. McKenzie County oil production change per month versus new producing wells added permonth from 2006 through June, 2015. ........................................................................................... 16

Figure 14. Mountrail County oil production change per month versus new producing wells added permonth from 2006 through June, 2015. ........................................................................................... 16

Figure 15. Williams County oil production change per month versus new producing wells added permonth from 2006 through June, 2015. ........................................................................................... 17

Figure 16. Other 11 counties oil production change per month versus new producing wells added permonth from 2006 through June, 2015. ........................................................................................... 17


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Bakken Reality Check 1

1Bakken Production Overview

Oil production in the Bakken Play of North Dakota and Montana, the birthplace of tight (shale) oil and the

number two tight oil play in the U.S., is now falling after more than a year of low oil pricesbut it has proven

more resilient than many observers expected. This paper reviews the latest developments in the Bakken Play

and provides an update of the assessment in my Drilling Deeperreport,1which was published in October

2014 just as the turmoil in the oil markets began.

Figure 1 illustrates Bakken production through June 2015. Production peaked in December 2014, at 1.21

million barrels per day (mbd) and has fallen 68,000 barrels per day, or 5.5%, since then. As of June there

were 10,886 producing wells in the play, compared to 10,025 in December 2014 (production data in this

paper are from Drillinginfo).

Figure 1. Oil production in the Bakken Play from 2003 through June 2015.

Also shown is the cumulative number of producing wells.

1David Hughes, Drilling Deeper: A Reality Check on U.S. Government Forecasts for a Lasting Tight Oil & Shale Gas Boom(Santa Rosa, CA: Post Carbon

Institute, 2014); http://shalebubble.org.


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More than 80% of the Bakkens cumulative production has come from four counties in North Dakota:

Mountrail, McKenzie, Dunn, and Williams (Figure 2). Half of the balance came from the Elm Coulee Field in

Richland County of Montana, where Bakken production first got underway in the early 2000s, and the

remainder has come from ten other counties in North Dakota and Montana.

Figure 2. Cumulative oil and gas production in the Bakken Play by county through July

2015.

Natural gas production is expressed in barrels of oil equivalent at a conversion rate of 6,000 cubic feet ofgas to one barrel of oil.


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The trend in the concentration of production within top counties has continued. As of June 2015, 35% of

production came from one county, McKenzie, and 89% of production came from the top four counties (Figure

3).

Figure 3. Bakken Play oil production by county from 2006 through June 2015.


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Figure 4 illustrates, however, that the bulk of the production decline has come from the top two counties,

McKenzie and Mountrail, with lesser declines in Dunn and other counties and flat production in Williams

County. This is counterintuitive as conventional wisdom suggests that companies are focusing drilling efforts

on their best acreage, which is in the top counties, and withdrawing from marginal parts of the play in order

to maximize economics in a low oil price environment.

Figure 4. Oil production in individual counties from 2006 through June, 2015.

The drop in rig count, from 198 in October 2014 to 68 today (September 2015), should by now, in theory,

have resulted in a precipitous collapse in the rate of addition of new producing wells. This has been muted,

however, owing to the completion of wells drilled earlier (termed DUCs: drilled but uncompleted wells), and to

greater efficiencies allowing more wells to be drilled by a single rig per unit of time (although such

improvements are likely to have been marginal over the past 10 months compared to earlier gains).


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Figure 5 illustrates the correlation between drilling rate and production. In order to maintain production at

the peak rate of 1.2 mbd, 157 new producing wells need to be added each month to overcome the static

production decline of the play, which in 2014 was 40% per year. The rate of well additions fell below this

threshold in January and production began to fall, although the rate of producing well additions remained

much higher than implied by the drastic drop in rig count given that many of the wells being added in recent

months were drilled during the period of high rig counts. The drop in rig count will manifest itself in steeper

production declines in future months as DUC wells are worked out of the system.

Figure 5. Bakken Play oil production change per month versus new producing wells

added per month from 2006 through June 2015.

A three-month trailing moving average has been fitted to the data.

Figure 5 indicates that to maintain a peak production rate of 1.2 mbd, 157 wells must be drilled each month

(1,884 wells each year). At a cost of $8 million per well, this necessitates investment of $15 billion per year,

not including operating, leasing and other ancillary costs. Stories of negative cash flows within shale

producers have been rampant in the media,2even at much higher oil prices. Many shale producers,

depending on the quality of their land holdings, cannot break even at oil prices of $50-$60 per barrel, hence

the prospect of attracting the level of investment needed to maintain Bakken production is slim indeed

unless oil prices rise substantially. Operators have been able to continue to complete and/or drill new wells

in the Bakken thanks in large measure to debt, but those days may be nearing an end.3

2Bradley Olson, U.S. Shale Drillers Are Drowning in Debt, Bloomberg, September 17, 2015; http://www.bloomberg.com/news/articles/2015-09-

17/an-oklahoma-of-oil-at-risk-as-debt-shackles-u-s-shale-drillers.3Stephen Gandel, Frackers could soon face mass extinction, Fortune, September 26, 2015; http://fortune.com/2015/09/26/frackers-could-soon-

face-mass-extinction.


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Figure 6 illustrates the average production per well by county. Average production is dropping in all counties,

which is to be expected as new wells comprise a smaller and smaller proportion of the total complement of

producing wells. A decline in the rate of addition of new producing wells will accelerate this trend.

Figure 6. Average production of Bakken wells by county from 2010 through June 2015.


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2Dominance of Sweet Spots

Sweet spotscore areas of high well productivityproduce most of the oil, as indicated by the fact that 89%

of Bakken oil in June 2015 was produced from four of 15 counties. Figure 7 illustrates the distribution of

producing wells in the Bakken categorized by well quality, as defined by initial oil production. As can be seen,

the actual area of highest quality wells constitutes a small proportion of the total play area and, even withinthe top four counties, the area of highest quality wells is only a portion of the total county area.

Figure 7. Distribution and initial oil production (highest month) of wells in the Bakken

Play of North Dakota and Montana as of June 2014.


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Figure 8 illustrates average type well decline curves by county and Figure 9 illustrates average oil EUR

(estimated ultimate recovery). The average well declines 86% in its first three years and 60% of a wells

ultimate recovery, assuming a 30-year life, is produced in the first four years. Given the difference in

production between the sweet spots and the rest of the play, it is easy to see why drilling has been focused

on the best parts of the top counties. In the longer term, however, drilling will have to move into lower quality

parts of the play as sweet spots become saturated with wells. Higher prices will be required to justify this.

Figure 8. Type well decline curves by county for the Bakken Play using data to year-end

2014.


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Figure 9. Estimated ultimate oil recovery (EUR) by county in the Bakken Play.

This average reflects the concentration of recent wells in the best parts of these counties.


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3Technology Improvement Meets Geology

A major theme in investor presentations is that wells are getting ever more productive through the use of

longer horizontal laterals, more fracking stages, and larger volumes of water, chemicals and proppants in the

fracking process. This has certainly been true over the 2011 to 2014 period although in 2015 it appears to

have met with the law of diminishing returns and the fact that there are only so many locations to drill insweet spots.

Figure 10 illustrates the average production rate over the first six months for new Bakken wells by county

from 2010 through 2015. Average productivity for the Bakken increased by 23% from 2012 to 2014 but

slowed to just 1% growth in 2015; it declined in the past year in McKenzie County, which produces 35% of

Bakken oil. Productivity has also declined since 2013 in Mountrail and Williams counties, and was flat in

Dunn County in 2015. The only increase in productivity in the past year has been in the other 11 counties

where a very limited number of new wells have been drilled in the highest quality part of this area (see well

addition rate inFigure 16 in the Appendix). These trends confirm an earlier analysis which showed that initial

well productivity has declining significantly in Mountrail County in recent months and declined slightly in the

Bakken Play overall.4

Figure 10. Average production rate of Bakken wells by county over the first six-monthsof production.

4David Hughes, Revisiting the Shale Oil Hype: Technology versus Geology, Post Carbon Institute, March 30, 2015; http://www.postcarbon.org/revisiting-

the-shale-oil-hype-technology-versus-geology.


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The failure of technology to boost average well productivity in top counties in recent months is due to:

-

Well saturation in sweet spots causing interference between wells.

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Exhaustion of the best drilling locations in sweet spots, necessitating drilling in lower-quality parts of

the top counties.

A further consideration is that although these improved technologies have allowed an individual well to drainmore of the reservoir at higher production rates, and hence have allowed the recoverable oil to be produced

with fewer wells, they will not necessarily increase the ultimate oil recovery of the play. Wells with

interference will allow the oil to be produced faster, but ultimately will represent higher capital cost inputs

than necessary to recover the resource.

The Bakken Play still has enough drilling locations available to triple the number of producing wells that have

been drilled to date, but these locations are increasingly in poorer quality rock. Thus the drilling rate will have

to be increased substantially, as well productivity decreases, in order to stem the steep intrinsic field decline

rate. These wells will also require progressively higher oil prices to be economic.


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4Future Outlook

Figure 11 illustrates historical production and the number of producing wells over time, as well as forecasts

of future production from the Energy Administrations (EIA)Annual Energy Outlook 2015(AEO2015)5, and my

Most Likely forecast from Drilling Deeper. Also shown is the number of new wells required through 2021 in

order to meet the production forecast from Drilling Deeper, and the EIAs historical data and short-term

forecast from its Drilling Productivity Reportfor September 2015.6

Figure 11. Historical production from the Bakken Play using Drillinginfo and EIA Drilling

Productivity Report(DPR) data.

Also shown are the Most Likely production forecast and number of wells required from Drilling Deeper, and

the production forecast from the EIA AEO2015 reference case. DPR data refers to the Bakken Region

which includes non-Bakken production.

Some observations:

-

Drilling rates have dropped below those assumed in the Drilling Deeper forecast, hence production is

currently slightly lower than projected.

-

The number of DUC wells (estimated to be914 in North Dakota as of July 20157) is sufficient tomaintain production on the plateau forecast in Drilling Deeperout to mid-2016, assuming the rig

count remains stable at current levels. Whether this happens or not depends in large part on oil

price and financing, as the North Dakota Industrial Commission has recently relaxed regulations

which required the completion of wells within one year of permitting. This effectively makes DUC

5Energy Information Administration, Annual Energy Outlook 2015, April 14, 2015; http://www.eia.gov/forecasts/aeo.6Energy Information Administration, Drilling Productivity Report, September 14, 2015; http://www.eia.gov/petroleum/drilling.7Lynn Helms, Directors Cut, NDIC Department of Mineral Resources, September 14, 2015; https://www.dmr.nd.gov/oilgas/directorscut/directorscut-

2015-09-14.pdf
https://www.dmr.nd.gov/oilgas/directorscut/directorscut-2015-09-14.pdfhttps://www.dmr.nd.gov/oilgas/directorscut/directorscut-2015-09-14.pdf


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wells an oil storage strategy for companies with deep enough pockets to forgo the cash flow from

putting these wells on production until prices go higher.

-

The EIA AEO2015 reference case forecasts continued growth in Bakken production to a plateau at

1.7 mbd in 2020, which is 42% above the December 2014 peak. It would require 2,700 wells per

year to maintain production of 1.7 mbd, and even higher drilling rates during the ramp up to that

levelassuming well quality stayed constant, which is unlikely given that sweet spot locations are

becoming saturated. Such drilling rates would exceed the highest levels ever achieved, whichoccurred in early 2014 when oil prices were $100/barrel, yet the EIA is suggesting oil prices will

remain below $75/barrel through 2021.

-

The most likely forecast from Drilling Deeperstill looks on track. The EIA forecast to 2021 is highly

unlikely, and in the longer term it is based on unrealistic estimatesof technically recoverable

resources.8Ramping up drilling rates to the level required by the EIA forecast would require much

higher oil prices and would exhaust available drilling locations before the middle of the next decade.

8David Hughes, Tight Oil Reality Check: Revisiting the U.S. Department of Energy Play-by-Play Forecasts Through 2040 from Annual Energy Outlook 2015,

September 2015, (Santa Rosa, CA: Post Carbon Institute); http://shalebubble.org/tight-oil-reality-check.


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5Summary and Implications

Bakken production is falling, which is a result of the decline in the rate of well completions to levels

insufficient to offset the static 40% yearly decline rate of the play (1,884 well completions per year are

required to maintain production at the peak level of 1.2 mbd).

Although rig counts have dropped by 65% since October 2014, the rate of well completions has fallen only

35% from the peak levels of mid-2014. This is due to the delayed completion of wells drilled when rig counts

were much higher. There was an inventory of some 914 drilled but uncompleted (DUC) wells in North Dakota

in July 2015. Bakken production will be supported by the completion of these DUC wells over the coming

months, even if rig count does not recover.

Well productivity gains have essentially stopped after a significant ramp-up in the 2012 to 2014 period. The

only recent well productivity gains were outside the top four counties, where drilling has moved to the best

quality areas from more marginal regions. Average well productivity in the Bakken will decline as sweet spots

become saturated with wells and drilling moves into lesser quality parts of the play.

The observation that new well quality is declining in top counties, despite every incentive to maximize

individual well production, is key. Pundits such as Morningstar, while bearish on the short term, areconvinced that rig counts and production will rise dramatically at prices of $60-$70 per barrel.9They miss

the point that the best quality parts of the play are being exploited now, and that lower quality geology going

forward will dictate lower well productivities, with worse economics, which will require higher prices to justify.

Thus even to maintain the peak rate of 1.2 mbd, the drilling rate would have to increase from the 1,884

wells per year currently required. To substantially increase production above the December peak would

require a return to rig count levels of triple current rates or higher, which would accelerate the consumption

of the finite number of remaining drilling locations. As noted in Drilling Deeper, high drilling rates serve to

recover the resource sooner, but do not result in a significantly higher ultimate recovery.

If sub-fifty-dollar oil continues, Bakken production will likely continue its decline until it reaches a level where

static field decline can be offset by completion rates, which are a combination of new drilling and the

inventory of DUC wells. Once these DUCs are worked off, completion rates will fall and production decline willsteepen until a balance between static field decline and the drilling rate is reached. Barring a substantial

recovery in oil price, the Most Likely Bakken production forecast in Drilling Deepermay prove to be

optimisticthis would push some projected oil production further into the future.

The EIA AEO2015 projection that Bakken production will continue to grow by 2020 to a plateau 42% higher

than the December 2014 peak would require more than triple the current rate of drilling activity, and much

higher prices to justify it. It would also require vastly more high quality drilling locations than are actually

available, given that it forecasts the recovery of more than twice as much oil by 2040 as the U.S. Geological

Survey (USGS) has estimated to be technically recoverable in its recent assessment.10Hence the EIA

forecast has a very low probability of occurring.

9Stephen Simko, US Oil Production Fall Will be Worse than Markets Expect, Morningstar, September 24, 2015;

http://www.morningstar.co.uk/uk/news/142447/us-oil-production-fall-will-be-worse-than-markets-expect.aspx.10Alex Demas, USGS Releases New Oil and Gas Assessment for Bakken and Three Forks Formations, U.S. Geological Survey, May 2, 2013;

http://www.usgs.gov/blogs/features/usgs_top_story/usgs-releases-new-oil-and-gas-assessment-for-bakken-and-three-forks-formations.


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6Appendix: Well Addition Rate Versus Production

Change and Total Production by County

The following charts provide county-level detail on rates of well completions and production change for thetop four counties as well as the group of other counties that make up the Bakken Play. Also noted are the

number of new wells that need to be added each month to offset the static field decline in each county.

Figure 12. Dunn County oil production change per month versus new producing wells

added per month from 2006 through June, 2015.



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Figure 13. McKenzie County oil production change per month versus new producing

wells added per month from 2006 through June, 2015.


Figure 14. Mountrail County oil production change per month versus new producing




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Figure 15. Williams County oil production change per month versus new producing wells

added per month from 2006 through June, 2015.


Figure 16. Other 11 counties oil production change per month versus new producing



hughes bakken reality check: the nation’s number two tight oil play after a year of low oil prices

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